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GHGT-10

Preparing the Ground for the Implementation of a Large-Scale CCS Demonstration in China based on an IGCC-CCS Thermal Power Plant :

the China-EU COACH Project

Francois KALAYDJIAN1a, ZHANG Jiutian

b, Paul BROUTIN a, Jens HETLAND

c, XU Shisen d,

Niels Eric POULSEN e, CHEN Wenying

f, Tony ESPIE g

a IFP Energies nouvelles, Rueil-Malmaison, France b The Administrative Centre for China's Agenda 21, Beijing, China

c SINTEF Energiforskning AS, Trondheim, Norway d Thermal Power Research Institute, Xi'an, China

e Geological Survey of Denmark, Copenhagen, Denmark f Tsinghua University, Energy Environment Economy Institute (3E), Beijing, China

g BP Alternative Energy, London, UK

Elsevier use only: Received date here; revised date here; accepted date here

Abstract

The COACH project (Cooperation Action Within CCS China-EU2) was launched on November 1st 2006 for a period of 3 years, as part of the 6th framework programme of the European Commission3. Gathering 20 partners comprising 8 Chinese partners and 12 European partners, the COACH project was conceived as contributing to the first phase of the Near Zero Emission Coal fired power plants (NZEC) programme, a 3-phase programme developed between the European Union and China, aiming at combating climate change by enabling the deployment in China of thermal power plants equipped with CO2 capture and storage (CCS) facilities.

The objective of the COACH project was to establish the basis for the large-scale use of coal for polygeneration in China with pre-combustion capture, transport and geological storage of CO2. Main efforts were place on a future CCS demonstration operated on an Integrated Gasification Combined Cycle (IGCC) thermal power plant fully equipped for converting and splitting the produced syngas into a hydrogen-rich fuel gas and CO2, and with a subsequent storage of CO2 in either mature hydrocarbon reservoirs (Dagang or Shengli oil provinces), deep saline formations or unmineable coal seams. Focus was made on the emission sources and storage sites located in the part of the Bohai Basin in the Shandong Province.

The paper will present the main outcomes of the project as follows :

1 Corresponding author. Tel.: +33-1-4752-6440; fax: +33-1-4752-7049.

E-mail address: francois.kalaydjian@ifpenergiesnouvelles.fr. 2 EC/FP6 Contract #038966, co-ordinated by F. Kalaydjian, IFP Energies nouvelles, France 3 The French Agency for Development (AFD) is gratefully acknowledged for its financial support to the dissemination, knowledge sharing and

capacity building activities developed in COACH

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2 Francois Kalaydjian / Energy Procedia 00 (2010) 000–000

• Structuring the China-EU COACH venture: In order to enabling the sharing of knowledge between European and Chinese COACH partners and building capacity a survey of CCS activities was performed, workshops were organised in EU and China, a cooperative website was created and two one-week long CCS schools were organised in China gathering more than 100 students 2/3 thereof coming from China and the remaining from Europe;

• Technical actions and challenges relating to CCS, gasification and polygeneration: A generic IGCC concept implemented with CO2 capture was defined and compared against a plain IGCC based on the GreenGen Phase I system without CO2 capture. A detailed analysis of technologies needed for implementing an option for CO2 capture in an IGCC process with provision for production of electricity and methanol was carried out as well as a cost analysis of both CO2

capture and transport;

• Geological assessment and storage sites mapping: A quantitative assessment of the potential storage sites (the Dagang and Shengli oil provinces, the deep saline aquifers nearby and the Kailuan coal mining area) was performed along with a mapping of the possible transport infrastructure (by pipelines or ships) that could be developed to connect CO2 sources to CO2

sites; with regards to storage capacity, the main capacity was found to reside in the deep saline aquifers (several giga tonnes) but would require further geological investigation for delivering definite values. The storage potential in oil fields was found to be much smaller (less than one giga tonne) but could provide opportunities for enhanced oil recovery. Finally, the coals of Kailuan mining area exhibit a high ability to adsorb CO2 and provide enhanced coalbed methane recovery, but their injectivity remains to be verified.

• Case studies and recommendations for CCS demonstration in China: By integrating results obtained in the previous tasks dealing with CO2 capture and CO2 storage, two scenarios (one small scale – from 0.1 to 1 million tonnes of CO2 per year, one large scale – 2 to 3 million tonnes of CO2 per year) were designed to screen options for a possible CCS demonstration project. These alternative CO2 streams are both considered captured from the GreenGen IGCC power plant in Tianjin and transported to one or more geological formations in the Bohai Bay geological basin for permanent disposal. Storage for the smaller scale scenario could be accommodated in the Dagang or Shengli oilfields. Storage for the larger scale scenario (2 – 3 million tonnes a year) could be accommodated in the Shengli oilfield province (in a number of fields) or potentially in the saline formations that can be found in the Huimin sub-basin area. For each of these options, a preliminary risk assessment was performed. A thorough cost analysis was performed.

• Policy and regulation issues pertaining to a shift towards CCS in China.

The 3-year targeted cooperative actions under the COACH project have mobilised capacities in China and Europe and paved the ground for subsequent CCS demonstrations in China. The next phase of the China-EU NZEC programme should start in 2010 and deliver FEED studies which should allow starting operating a CCS demonstration in China by 2015.

© 2010 Elsevier Ltd. All rights reserved

Keywords: IGCC, polygeneration, CCS knowledge sharing and capacity building, CCS demonstration, CO2 storage capacity assessment

1. Introduction

Following the EU-China joint declaration on climate change published on September 2005, an EU-China cooperative action - COACH - was launched on November 2006 with the objective to initiate a strong and durable cooperation between Europe and China in the domain of clean coal-based power generation to respond to the fast growing energy demand of China while reducing its impact on the climate. Taking advantage of the combination of European and Chinese technologies, the COACH project was conceived as a first step preparing the ground for enabling the implementation of large-scale coal based polygeneration energy power generation facilities with options for electric power generation including the production of synthetic fuels and provisions for heat integration with surrounding

c⃝ 2011 Published by Elsevier Ltd.

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industries. In this endeavour the CO2 was to be captured from an Integrated Gasification Combined Cycle (IGCC) coal power plant and then transported and stored deep in the underground in an appropriate geological setting – deep saline formation, mature oil field or unexploitable coal seams. Though technically feasible, the associated production of hydrogen and its further utilization was decided to not be addressed in the project. A consortium4 has been established in order to assemble resources, skills and proficiency as well as industrial determination of leading European and Chinese institutions and companies.

COACH has dealt with three techno-economic issues: (1) coal gasification for appropriate coal-based polygeneration schemes combined with CO2 capture and storage; (2) identification of CO2 emission sources of interest as well as reliable geological storage capabilities of CO2 in the Bohai basin located in the Shandong province and schemes for transport infrastructure connecting sources to sinks; (3) legal, regulatory, funding and economic aspects. In addition to that, COACH organised activities for contributing to the sharing of knowledge between China and Europe and the building of Chinese capacity.

To reach these objectives, COACH comprised 4 workpackages, co-led by European and Chinese partners addressing respectively, knowledge sharing and capacity building issues, identification of appropriate CO2 capture and CO2 storage technologies and then recommendations and guidelines for implementation. The main results obtained in these workpackages are presented in the following sections.

2. Knowledge sharing and capacity building

To tackle the issue of sharing knowledge and building capacity, the project assigned to itself three tasks: (1) organising workshops, (2) enhancing information exchange and dissemination of results, (3) organising mobility schemes and education.

In order to enhance information exchange several actions were taken: presentation of the activity at several international conferences, publication of papers in academic and professional journals, publication of books making reference to the COACH project. In order to disseminate further the results of the project a public website www.co2-coach.com was created, a presentation of the project was published in the European Parliament Magazine and several interventions in radio broadcasts were organised. Finally a survey of CCS activities in both China and Europe was carried out and updated during the project.

Regarding capacity building, during the 3 years of the project, almost 10 workshops were organised in China or in the EU, either by the COACH project alone or in association with related projects either funded by the EU (StraCO2, Geocapacity, ...) or by the UK governement (UK-China NZEC). Training sessions and workshops organised in China allowed to gather not only the researchers involved in the project but also to meet and discuss with students the main outcomes of the project and CCS issues in general. In addition to that a mobility scheme was put in place by which stays of researchers and students were organised by European and Chinese partners. What is worth being noticed is also the organisation of two one-week long CCS schools that were held during the last year of the project in Hangzhou and in Beijing. These two schools attracted more than one hundred students in total, that passed a selection process, 80 of them coming from China and 30 from Europe thus enabling a cross-fertilisation between Chinese and European students featuring the next generation of scientists. The team of teachers was composed of both European and Chinese scientists.

3. Capture technologies

Four main tasks were carried out in this workpackage. They consisted in (1) an inventory of power generation and optional carbon capture, (2) concept studies for coal-based plants with carbon capture in China, (3) potentiality studies of polygeneration schemes linked with coal-based plants in China and finally (4) providing recommendations for pre-conditioning of CO2 for transfer from a power plant to a storage site in China.

Modern Chinese plants - larger than 300 MWe that have gone into operation after the year 2000 - have been targeted for identification. These plants have been subjected to assessment and screening on a typological basis for possible upgrading or for integration with a plausible capture technique. Pursuant to emerging CO2 capture techniques, China has decided to place efforts on coal-gasification partly because of the higher development potential of the IGCC and partly because gasification inherently leaves an option for polygeneration (multiple yields) that also facilitates the capturing of

4 For Europe, 12 partners were involved in the consortium : Services Petroliers Schlumberger, Alstom Power Ltd, Air Liquide, BP International Ltd,

STATOIL, Shell International Renewables BV, IFP Energies nouvelles, SINTEF Energiforskning AS, Geological Survey of Denmark and Greenland, Natural Environment Research Council – British Geological Survey, Kungliga Tekniska Högskolan, and ATANOR. For China, 8 partners were involved in the consortium : RIPED, the Research Institute of Petroleum Exploration & Development – Langfang, attached to the Chinese oil company PETROCHINA and Greengen Ltd, the Tsinghua University, the Zhejiang University, the Institute of Engineering Thermophysics of the Chinese Academy of Sciences, the Thermal Power Research Institute, the Institute of Geology and Geophysics of the Chinese Academy of Sciences and the Administrative Centre for China's Agenda 21.

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CO2. However, in deployment of integrated gasification combined cycle schemes (IGCC) with multiple yields and with CCS, the reliability and availability must be improved, and likewise the capital and operational expenses should be reduced. This requires insight in optional technologies about coal gasification, syngas pre-treatment, air separation and various schemes for polygeneration as well as the pre-conditioning and transport of CO2. Efforts have been made to assess promising schemes for co-production of electricity and synthetic fuels, whereof the latter is intended for the future transport sector in China such as hydrogen and synthetic gasoline.

With regards to gasification, the flagship of China is the GreenGen demonstration project (Phase 1, 250 MWe), which is an autonomous IGCC demonstration scheduled to become operational in 2011. The GreenGen will further evolve into a larger unit with CCS by 2015 (400 MWe). The strategic importance of the IGCC is that it may lessen China’s dependency of imported petroleum (oil and gas). This is due to the ability of polygeneration schemes to co-produce synthetic liquid fuels and gas, chemicals and electricity from indigenous coal.

A generic IGCC concept that employs CO2 capture (i.e. IGCC-CCS) has been defined and compared against a plain IGCC (similar to GreenGen Phase 1 without CO2 capture). Both cases are tied to the regulated price of electricity in China, assumed to correspond to conventional coal-based power generation. Definition of the two cases was made according to preferences raised by Chinese partners of using a generalised IGCC scheme. Both cases are made up by an oxygen-blown gasifier dry-fed with pulverised coal, and a down-stream combined power cycle. The power island comprises the gas turbine, the heat recovery steam generator, the steam turbine, compression of nitrogen for dilution in the combustor, injection of steam and condensation of steam. Whereas the reference case uses a gas turbine that burns a low-calorific syngas and with no further gas cleaning than a conventional IGCC, the base case (Fig. 1) is made up by a generic gas turbine fuelled with a hydrogen-rich gas mixture that is diluted with nitrogen, and with a pre-combustion capture process that removes (and stores) about 90% of the CO2. It furthermore includes a compression system that leaves the captured CO2 in dehydrated and dense phase at pipeline pressure (selected to be 110 bar). Available technologies, including the production of hydrogen, ammonia, methanol, DME, and diesel have also been addressed, although they were not reviewed in detail for integration with these schemes.

Figure 1 : Base case – electricity production with CO2 capture

Figure 2 : Capture cost and cost of avoided CO2 versus number of operating hours of the plant per year.

3.1. Benchmarking

The benchmarking was made under a subset of prerequisites specific to China5. At the current state-of-the-art development the cost of electricity (COE) of an IGCC is expected to be almost 20% higher than the prevalent price (i.e. 0.327 RMB/kWh as of summer 2009). Additionally, the inclusion of CCS will add another 2/3 of the COE of the IGCC (GreenGen Phase 1). However, the availability of the plant is an important factor, and it should be a target to develop the system for at least 7500 operating hours per year – in line with European IGCC projects (Fig. 2). The capture cost amounts to almost 180 RMB/tCO2 (~ 18 €/tCO2

6) and the cost of avoided CO2 is 225 RMB/tCO2 (~ 22 €/tCO2).

3.2. CO2 handling

In order to dispose of the CO2 in a stable sink – either in geological formations or for making additional use of the CO2 for EOR/EGR (enhanced oil recovery / enhanced gas recovery) the necessity of CO2 pre-treatment has been duly addressed. The pre-requisites and conditions are reflected in a sub-set of requirements pertaining to the down-stream gas transfer and storage systems relating to future carbon capture plants in China. This includes mechanical and

5 Construction time: 4 years, repayment time: 15 years, working time: 20 years, interest rate: 7.83%, electric price: 0.327 RMB/kWh, working

hours per year: 7000 hours (and 5000 hours for reference and scaling). 6 Assuming in the whole paper an exchange rate : 1€ = 10 RMB

POX Gasifier Sour WGSR CO2 and H2Scapture CCGT Power Unit

Air SeparationUnit

Water TreatmentSteam flow

Material flow

ElectricityCoal

Air

Condensate Condensate

Rawsyngas

Air

CO2 + H2S transportand storage

H2H2+CO2

OxygenNitrogen

150

170

190

210

230

250

270

290

310

330

350

5000 5500 6000 6500 7000 7500 8000 8500

Number of operating hours per year

Cos

t [R

MB

/tonn

e C

O2]

Cost of avoided CO2

Capture cost

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metallurgical integrity of the CO2-handling system to avoid corrosion that eventually may lead to gradual or abrupt leakages, and further thresholds for possible impurities in compliance with HSE requirements for safe transport and also for stable storage conditions. Pressure and temperature are important criteria in the handling of CO2, in particular if the CO2 has to be piped or transported in tanks over some distance, which usually requires that the CO2 is transformed into a dense phase (either cryogenically or supercritically). In order to assess the tail-end impacts of the CCS concept, a case-based study was conducted along three alternative routes (pipeline, ship, railway), all taking delivery from the CO2 that is captured from the GreenGen demonstrator in Tianjin (R1, Fig. 3) to the storage site in the Shengli oilfield province (Point B). For the two latter routes cryogenic conditions were used at a meso pressure (~ 8-10 bar), whereas a pressure of 110 bar was assumed for the pipeline.

Figure 3: CO2 transport cases linking the GreenGen plant (R1) to the Shengli Oilfield Complex (B)

via pipeline, by ship or by railway.

Figure 4: Location of GreenGen power plant and

Dagang and Shengli oilfield provinces

4. Geological CO2 storage and large scale use of CO2

Potential CO2 storage sites have been investigated in the part of the Bohai basin located in and near the Shandong province, East China. Selected oilfields, saline aquifers and unmineable coal beds were considered. Two main tasks were carried out : (1) capacity estimate at regional level, (2) mapping of the geology and point emission sources.

4.1. Capacity estimate at regional level

The aim of this task was to assess the CO2 storage potential of oilfields, deep saline aquifers, and coals using published data. The potential of enhanced oil recovery (EOR) by CO2 injection was also assessed. The majority of large sources of carbon dioxide (CO2), lie along the eastern coastline and consequently storage sites are being sought in this area. The storage sites considered were the Dagang oilfield province (Tianjin Municipality), Shengli oilfield province (Shandong Province), Kailuan mining area (Hebei Province) and deep saline aquifers in the Jiyang Depression (Shandong Province) (Fig. 4). As security of energy supply is key consideration for China, investigation into potential storage capacity was carried out for the Dagang and Shengli oilfields and enhanced oil recovery (EOR) was evaluated for selected Shengli oilfields. A CSLF-based methodology[1] was applied to evaluate storage potential of the Dagang and Shengli oilfields. The Shengli oilfield province was also evaluated using a model created by the China University of Petroleum (CUP) Beijing based on dissolution of CO2 into pore water and oil.

Oilfields/ The overall storage potential of the seven selected fields in the Dagang oilfield province was estimated at about 22 Mt, of these fields, the Gangdong Oilfield had the largest estimated storage potential of 10 Mt CO2 in the Guantao Formation. Average porosity and permeability of the sandstone reservoirs in the Gangdong Oilfield are 31% and 975 mD respectively.

The storage potential of selected fields in the Shengli oilfield province was estimated to be 472 Mt using the CSLF-based methodology and up to 463 Mt using the CUP Beijing methodology depending on remaining oil reserves in the oilfields, as the most recent publicly available data are from 2000. These oil reserves generally lie below 1000 m. The Shengtui Oilfield was calculated to have the greatest potential storage capacity; 186 Mt using CSLF-based methodology and 117 Mt using the CUP Beijing model. Average porosity of the reservoirs of the fields evaluated is 31%. Data for the Gudong Oilfield indicated porosity of 28 – 35% and permeability of 510 – 3118 mD [2,3] in the Guantao Formation. The potential for recovering additional oil from the Shengli oilfield province by EOR was calculated to be approximately 23–112 Mt using recovery rates of 2 – 10%.

R1

A

B

Railway route

Pipeline

Ship route

Shengli oil field complex (EOR)

Tianjin power plant

route

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Coal seams/ Kailuan mining area lies in the north Bohai Basin and contains 3750 Mt of coal reserves of Carboniferous and Permian age mostly lying at depths greater than 1000 m. Storage and enhanced coalbed methane (ECBM) recovery were considered. As Kailuan is an active coal-mining area, CO2-ECBM could only be applied at selected sites where there is no risk of damaging the future energy resource or leakage through contact with future, active or abandoned coal mines. Site screening determined that uneconomic seams are present at suitable depth for CO2 storage. Adsorption experiments as well as thorough chemical analyses were carried out on coals from Majiagou Mine and Linnancang Mine for estimating their adsorption potential. These coals are considered to be representative of coals from this mining area and so were used to imply properties for deeper, unmineable coals. Other coal samples from Kailuan mining area were also examined to determine porosity and permeability. These properties were determined to be generally low with the most favourable porosity and permeability found in the Early Permian Taiyuan Formation coals with porosity 3.7% and permeability 3.6 mD. Storage in all the coal seams in the Kailuan Mining Area was calculated (CSLF method) to be 504 Gt. However, not all this capacity can be considered available for storage as some of these seams may be mined in the future and permeability is generally low so not all the coal could be accessed.

Deep saline aquifers/ The oil-bearing Jiyang Depression lies in the central Bohai Basin. It covers an area of around 20,000 km2 and is subdivided into six sub-basins. Through initial site screening, the Guantao Formation was determined to show the most promise; at suitable depth (greater than 1000 m), presenting a broad areal distribution and good connectivity between fault blocks. After further site screening, the Huimin sub-basin basin within the Jiyang Depression was selected for further study and the potential for storage in this region was evaluated. The Linfanjia and Shanghe oilfields in the Huimin sub-basin have average porosities of 31% and 19 % respectively and measured permeabilities of 390 mD and 11 – 150 mD. There is more uncertainty in estimation of aquifer storage potential as a result of limited data availability due to general lack of commercial interest in deep saline aquifers. Storage capacity for the Huimin sub-basin was estimated to be 22 Gt. Further research is required to identify closed structures as targets for storage.

Based on these storage site potentials, it is considered that the capacity of the Dagang oilfield province is not sufficient for large-scale storage, though there is potential for a small scale pilot in storage or EOR pilots. The capacity is quite small and injection would be complicated by the structural and lithological variability of the reservoir. The Shengli oilfield province, located more centrally in the Bohai Basin was considered more promising but still limited. Storage potential in the Kailuan mining area is limited by permeability of the coals. On initial evaluation, the Guantao Formation in the Jiyang Depression has a large potential storage capacity, though this should be considered with caution as it does not have the benefit of proven ability to store buoyant fluids and less data are available for detailed evaluation of the storage potential.

4.2. GIS mapping of the geology and point emission sources

The aim of this task was to produce inventories for CO2 emissions, infrastructure and potential CO2 sinks which were to be compiled into a Geographical Information System (GIS) and a web-based Geographical Information System. The storage capacity data in the databases were calculated using the CSLF method. The CUP storage capacity data for the Shengli oilfield province, based on the Tanaka et al. (1995) method[4], are also recorded.

Part of the focus of this task has been on large stationary CO2 sources, such as power plants, ammonia production plants, iron and steel production plants, cement kilns and oil refineries. The electricity generation and industrial sectors offer the best potential for large-scale, centralized capture of CO2. There are three oilfield provinces around the Tianjin IGCC power plant. They are Huabei, Dagang and Shengli oilfield provinces. Storage potential in the Huabei oilfield province, which was estimated in GeoCapacity project7, is used alongside data gathered in this project to establish comparisons between different matching pathways for Tianjin IGCC power plant[5]. Dagang oilfield province is the nearest potential storage site, but is not suitable for large-scale storage, though could be considered for EOR pilots. Therefore, as the distance between GreenGen IGCC power plant and Huabei and Shengli oilfields are similar, these two oilfield provinces were selected for the source and sink matching exercises.

5. Integration and recommendations

With the identification of emission sources in the region of interest and estimates of storage capacity, options for source-sink matching were first investigated maximising either the economic performance or the storage capability. Then, two specific scenarios for a possible future demonstration of CCS have been used to focus this study. These are geographically focused upon the Bohai Basin region in the North East China (Fig. 4). Capture studies have been based upon a hypothetical polygeneration plant that is loosely modelled upon the Greengen Tianjin IGCC plant and storage studies have considered at a high level (they do not in themselves provide a sufficiently detailed assessment to enable any meaningful site selection at this stage) the Dagang oilfield province, the Shengli oilfield province, the Huimin sub-basin saline formations, the Kailuan mining area.

7 EU FP6 funded project

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Regarding the oilfields (Dagang and Shengli), in addition to their storage capacity reported in section 4, attention was paid to their reservoir engineering characteristics (geological structure (fluvial deposit), number (700 in the Gangdong field) and age of wells (up to 40 years old for Shengli). For both oil provinces, compartmentalization, multi-reservoir organisation with poor communication and well integrity were found to represent significant issues. However, as those fields are in the declining phase of production the potential must exist to undertake pilot CO2 floods and the potential for a conflict of interest between a pilot CO2 flood and other field operations is probably not high.

With 2-3 Mt/year for the larger project coupled with the economic modelling lifetime implies the need for 60 Mt storage for a demonstration project.

Based on the conclusions on storage site potentials, it is considered that the capacity of the Dagang oilfield province is not sufficient for large-scale storage, though there is potential for a small scale pilot in storage or EOR pilots. The capacity is quite small and injection would be complicated by the structural and lithological variability of the reservoir. The Shengli oilfield province, located more centrally in the Bohai Basin was considered more promising. Storage potential in the Kailuan mining area is limited by permeability of the coals. On initial evaluation, the Guantao Formation in the Jiyang Depression has a large potential storage capacity, though this should be considered with caution as it does not have the benefit of proven ability to store buoyant fluids and less data are available for detailed evaluation of the storage potential.

Thus, the two scenarios may be thus summarised as follows :

Region Bohai Basin region in the North East of China

CO2 source 3rd phase of GreenGen (Tianjin, 2012-2015)

Transportation Pipeline

Feedstock Shenhua coal, railway transport from Inner Mongolia

Gasifier TPRI / GreenGen

Yields Power and methanol

Scenario A (Small scale) Scenario B (Full scale) CO2 amount 0.1-1 million ton /yr 2-3 million ton /yr CO2 sink EOR (Dagang or Shengli) Saline aquifer (Jiyang Depression or other)

5.1. Cost analysis

For this cost analysis a single product (electricity) was considered and the CO2 conditionning and compression are included within the cost of capture. Cost of CO2 captured and avoided were calculated assuming 7000 operating hours per year. Regarding transport (Dagang: 70km, Shengli: 200km, Huimin: 250km, Kailuan: 170km), the CO2 flowrate was assumed to be 3 Mt/yr with a pipeline with 300mm in diameter. For a facility lifetime of 20 years, and pipeline CAPEX (resp. OPEX) of €21,500 in-mile (resp. €3450/mile/year) the unit cost for a 100 mile pipeline was found to be €0.55/t.

Regarding storage, appraisal costs (2D, 3D seismic survey, appraisal wells) were estimated leading to a unit cost of €0.83/t. Drilling of new wells as well as remediation or upgrading of existing wells were also considered leading to a unit cost ranging from €0.67/t (no remedation) to €4.67/t (remediation max). Monitoring was estimated to add another €0.83/t cost.

All cases considered lie in the range €26–30 /tCO2 avoided8, this cost being dominated by the cost of CO2 capture, conditioning and compression (80 – 88% of total).

5.2. Policy and regulation

For building an operative regulation framework, guidance was taken from the CO2 capture project which considers the four following steps: site certification, operation (from metering to report of performance), closure (up to the transfer of responsibility) and post-closure. A summary of the activities carried out in a number of countries (EU, USA, Canada, UAE, Australia) with respect to regulatory requirements of CCS was then carried out. Regarding the initiatives within China the COACH project liaised with the Tsinghua University and the the STRACO2 project.

6. Conclusions

The COACH project has provided the following main results :

8 It should be stressed that these costs have a considerable uncertainty associated with them and should be treated as indicative only

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- Knowledge Sharing & Capacity Building/ An important activity was deployed to perform an efficient knowledge sharing within the project. As such several workshops were organised both in China and in Europe, several sometimes in conjunction with companion projects such as UK-China NZEC, StraCO2, GeoCapacity. A public website www.co2-coach.com was created. A survey of CCS activities in both China and Europe was carried out and updated during the project. Regarding capacity building, in addition to the training sessions and workshops organised, two one-week long CCS Schools were set up attracting in total 80 Chinese students and 30 European students.

- Capture technologies/ A generic IGCC concept implemented with CO2 capture has been defined and compared against a plain IGCC based on the GreenGen Phase I system without CO2 capture. Benchmarking was made between a reference case for which a gas turbine burns a low-calorific syngas and a base case consisting of a turbine burning a hydrogen enriched gas mixture diluted with nitrogen. Provision for methanol production was made as well but was not reviewed in details. The CO2 capture cost was found to amount to €22/tCO2 whereas the cost of the avoided CO2 was a little bit higher amounting to €27/tCO2. CO2 handling was also addressed for transporting and storing the CO2 safely. Three cases were studied for transporting the CO2 from the Tianjin power plant to the Shengli oilfield region, by rail, pipeline and ship.

- Storage/ Potential CO2 storage sites have been investigated in the part of the Bohai Basin located in and near the Shandong province, East China. Selected oilfields, saline aquifers and unmineable coal beds were considered. Possible test sites are available in some of the oil fields. The coals of Kailuan mining area have a high ability to adsorb CO2, but the CO2 injection rate is anticipated to be low. ECBM recovery could be considered. The aquifers show a large storage potential, but further geological investigation is required. Some of the oilfields may be suitable for an enhanced oil recovery pilot. Injecting CO2 into an mature oil reservoir cannot only store CO2, but also enhance the oil recovery. The storage potential in oil fields is however much smaller (10–500 Mt) than in the saline aquifers (~20 Gt).

- Integration/ Two scenarios have been designed to screen options for a possible CCS demonstration project. These have considered capture of CO2 from the Tianjin IGCC power plant and storage in one or more geological formations in the Bohai Bay geological basin. Storage for the smaller scale scenario (0.1–1 Mt/year) could be accommodated in the Dagang or Shengli oilfields. Storage for the larger scale scenario (2–3 Mt/year) could be accommodated in the Shengli oilfield province (in a number of fields) or potentially in the saline formations in the Huimin sub-basin area. For each of these options, a preliminary risk assessment was performed. Furthermore, a thorough cost analysis was performed. This lead to an integrated CCS cost which was found to lie in the range € 26-30 / tCO2. Finally, policy and regulation issues were addressed.

These results are detailed in companion papers presented at this GHGT-10 Conference.

References

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